The two most common impurities in natural gas are hydrogen sulfide and carbon dioxide, called acid gases. In order to make the contaminated gas suitable for use and sales requires removal of the hydrogen sulfide (H2S), and often partial removal of the carbon dioxide (CO2) component.
Some of the known processes for purifying natural gas utilized offshore are amine absorption and regeneration, solid absorbents, liquid scavengers, and catalytic oxidation. The amine and solvent-based systems have large heats of regeneration, large energy requirements, large cooling loads, and fresh water make-up. Solid absorbents are only applicable to H2S removal and create material handling problems, both with the loading, unloading, and disposal of the spent solid activities that are particularly difficult, hazardous and time consuming on an offshore platform.
The amine sweetening system produces a waste gas stream consisting principally of hydrogen sulfide gas. The gas can be flared but produces sulfurous acid, a corrosive and toxic air pollutant, regulated under the Clean Air Act. Accordingly, it is an object of this invention to provide a method which enables a more economical and convenient means of treating the natural gas.
An example of where removal of H2S and CO2 from a gas stream is necessary can be found during the production of natural gas on an offshore production platform. The H2S must be removed for a number of reasons. First of all it is lethal, and at low concentrations it has a very disagreeable odor. It promotes the formation of hydrates in the downstream systems and causes sulfide stress cracking of carbon steel. On the other hand, CO2 in natural gas is objectionable because it is an inert and reduces the heating value. H2S and CO2 are commonly referred to as acid gases. In the U.S., the H2S content of natural gas is nearly always limited to 0.25 gr/100 scf (4 ppmv) and specifications can be as low as 1 ppmv in some countries. The CO2 content is often limited to 2.0 vol % in the U.S.
A variety of processes have been developed for removing acid gases from natural gas. Only a select few have been applied to offshore gas production. In general, the most common processes include selective absorption by solid absorbents, reaction and physical solution by selective solvents, reaction with specific chemical agents, and so forth. The selection of the process depends on the volumes of gas to be treated, and the acid gas concentrations.
Although a few processes have proved successful for acid gas removal in offshore applications, they are usually energy intensive, operationally complex, requiring large, expensive equipment, continual operational attention, and need an additional process step to convert the H2S to sulfur. This step is usually referred to as a sulfur removal unit (SRU).
One typical solvent adsorption process is amine sweetening, utilizing ethanolamine solvent such as MEA, MDEA and DEA. The solvent is circulated to the gas contactor, where it removes the H2S, then to the condensate separator, the rich/lean amine exchanger, and is regenerated in the stripper/reboiler section. Heat is required, usually by way of a gas-fired boiler to regenerate the amine, creating a potential fire hazard on an offshore platform that has limited space to separate process equipment. The reboiler feeds the stripper column that also requires an air or water-cooled condenser to condense the amine to minimize losses. The regenerated amine, still hot from the stripping process, must be cooled before being pumped and returned to the contactor. Typical energy requirements are 20-40 MMBtu/hour, plus 500-1000 horsepower to drive the pumps and coolers.
In addition, there is a requirement of fresh make-up water. These systems cost from $10-20 million and occupy a large area of the platform. The system must be constantly monitored for solution strength, impurities, corrosion inhibitors, and the addition of fresh solvent, as there is a constant solvent loss with the treated gas. The by-product of the process is a concentrated acid gas stream that usually cannot be flared. A second system is required to remove the H2S and convert it to sulfur. This additional step, usually referred to as an SRU, is also a complex system, costing several million dollars and occupying more area on the already limited offshore platform. The SRU also requires continuous and routine operational attention and maintenance.
The system envisioned here would overcome these shortcomings. Seawater scrubbing as presented herein does not require any heaters, there is no make-up solvent or fresh water requirement, the equipment is simple and can be remotely or automatically controlled, creates no acidic gas stream that requires additional treatment, has a minimum of pieces, and low energy requirements.